Presently, low pressure reservoirs, incapable of producing fluid from the reservoir to the surface naturally, account for over 90% of the hydrocarbon producing wells in the United States. There are various means of pumping fluid from these wells, such as the use of sucker rod pumps, hydraulic pumps, jet pumps, and semi-submersible electric pumps. Most of these low-pressure wells produce fluid at too low of a flow rate for the majority of the current art pumps to operate efficiently.
The most common system for producing these low pressure, low flow rate wells is through the use of sucker rod pumping systems. Sucker rod pumping systems include a downhole plunger and cylinder type pump connected to a surface unit by means of rods or sucker rods. This surface unit is commonly referred to as a pump jack. The present art sucker rod systems have several limitations and problems. One problem is that while the stroke length of the pump and the strokes per minute may be controlled through the selection of the pump jack size. Pumping jacks are expensive and each pump size is adapted for a specific range of flow rates and depth of the reservoir. Once the pump unit is placed it is cost prohibitive to change the pump jack. Another problem with these systems resides within the use of the sucker rods. Sucker rods are metal or fiberglass rods which are connected together to form one continuous string of rods often several thousand feet in length when used in hydrocarbon wells. These rod strings are connected usually by the use of pin and box connections. The process of connecting the rods string when running into the hole or disconnecting the strings when pulling out of the hole is time consuming and costly. Additionally, the length and weight of these rods and the reciprocation of the rods produced by the pump jack results in failure, commonly by parting, of the sucker rod string. Another problem is that the sucker rod string is positioned within a tubular string such as tubing. When the system is operating the rod string commonly contacts the tubular string at several points which results in wear of both the rod sting and the tubular string resulting in failure of the well. Some studies have shown that these rod pumping systems fail on the average of once every six months resulting in significant repair and maintenance costs, often making producing the well uneconomical. Failure rates in rod pumping systems greatly increase with the deviation of the well bore from vertical.
There have been attempts to develop a pumping system which utilizes the plunger/cylinder type downhole pump while eliminating the use of sucker rods and the related problems. These prior art rodless pump systems typically include a surface unit, which is connected to a subsurface pump by a fluid conduit such as the tubing string. The surface unit activates the subsurface pump by applying pressure to the fluid in the tubing string to compress a spring means in the subsurface pump and displace a slidable piston to draw fluid from the well into a pump chamber. When the surface unit releases the fluid pressure, a spring mechanism in the subsurface pump will displace the piston and lift the fluid into the pump chamber into the tubing string and to the surface. Such systems are disclosed in U.S. Pat. Nos. 2,058,455; 2,123,139; 2,126,880; and 2,308,609. Although, these prior art systems eliminate the rod string they utilize a compression spring for lifting the produced fluid into the tubing string. These springs severely limit the stroke length and thus the flow rate of the pump and also tend to fail due to wear and or the accumulation of trash carried into the pump.
Other prior art rodless pumps such as disclosed in U.S. Pat. No. 4,297,088 replaces the physical spring with a gas chamber. When pressure is applied to the tubing string, a piston will compress the gas within the chamber and, when the pressure is relieved, the gas will expand to lift fluid into the tubing string. These systems allow for a very long stroke length and thus much higher efficiency, but introduces additional problems. A major problem with these prior art pumps is that unlike sucker rod pumps the rodless pumps do not have a precisely defined stroke length. In these rodless pumps, the stroke length is affected by the length of time the surface unit applies pressure to the fluid in the tubing string on each cycle. It is also affected by the compressibility of the fluid in the tubing string and the amount of ballooning of the tubing that occurs. The stroke length is also influenced by the pressure in the gas chamber, since the pressure in the gas chamber must be sufficient to support the hydrostatic pressure of the entire column of fluid back to the surface at the end of the downstroke, the plunger has enough force being applied to it at the end of the downstroke to cause it to strike the limit stop in the barrel with a sever impact. Also since the surface unit will not stop pressuring the tubing at the precise moment to prevent contact, the plunger will impact the limit stop on this end of the stroke. Thus, unlike sucker rod pumps, these pumps are difficult to design in a manner such that the maximum stroke may be utilized without the plunger contacting the barrel at the end of the upstroke and downstroke. This contact severely limits the life of the pumps.
Another prior art rodless pump disclosed in U.S. Pat. No. 6,155,803, overcame the limitations regarding the severe plunger impacts, as discussed above, at the end of each stroke. However, that rodless pump system still utilized a downhole gas source within the pump to force that plunger assembly downward after the surface pressure source released the pressure being exerted on the downhole pump. The gas pressure source required a substantially self contained pressure chamber containing a substantially compressible fluid. This chamber was part of the pump and was positioned downhole. The chamber was also preferably precharged with a gas such as nitrogen. Although this arrangement was an improvement over prior art, particularly involving the plunger impact, it still proved to possess some inherent limitations. These limitations included a requirement of a very high precharge pressure in the gas chamber, a possible short life of the pistons, due to fluid leakage and contamination, and a requirement of bleeding the substantial gas chamber pressure whenever bringing the pump to the surface. The current device is an improvement of this prior art particularly with respect to eliminating the downhole gas source or gas pressure chamber within the pump.
It is thus a desire to have a rodless pump system which overcomes the limitations and problems of the prior art pumps. Thus, this pumping system utilizes a combination of two conduits, one conduit being connected to a pressure source and the second conduit containing a balance fluid extending to the surface thereby eliminating the need for the downhole gas chamber previously required to lift the hydrostatic fluid to the surface. This arrangement greatly reduces the surface pressures required to operate the system thus eliminating the pressure limitations encountered at relatively shallow depths by prior systems and eliminates the limitations imposed with the downhole gas source.
In a common oilfield application the pump would be connected to the bottom of a tubing string within the reservoir fluid to be produced. A pressure sources such as a hydraulic pump would be connected at the surface to the tubing string so as to selectively apply pressure by way of the fluid in the conduit to the pump, raising the plunger assembly in the pump drawing reservoir fluid into the pump. As the plunger assembly moves upward it raises the fluid contained in the second conduit an equal distance thereby creating an imbalance in hydrostatic pressures of the two fluid columns interfacing at the downhole pump. When pressure generated by the surface pressure source is released, the imbalance between the two conduits forces the plunger assembly downward in the pump pushing the reservoir fluid in the pump into the tubing string and upward toward the surface.
Preferably, the pump includes dampening mechanisms at both the top and bottom of the plunger's stroke so as to reduce metal to metal impact within the pump at the end of the top and bottom of the each stroke of the plunger assembly. The dampening mechanism may include but is not limited to an elastomer barrier, a spring, and dampeners such as discussed further below. Several different configurations may be used singularly or in combination to reduce the metal to metal impact and increase the life of the pump.